Surface multiple well

ABSTRACT

An offshore oil production system, comprising a structure in a body of water, having a portion extending above a surface of the body of water; a surface wellhead located at a top of the body of water; a first wellhead located at a bottom of the body of water; a second wellhead located at a bottom of the body of water; a first riser extending from the first wellhead to the surface wellhead; and a second riser extending from the second wellhead to the surface wellhead.

BACKGROUND OF INVENTION

1. Field of the Invention

The present invention is directed to multiple risers located within asingle wellhead for deepwater applications.

2. Background Art

U.S. Patent Application Publication 2010/0126729 discloses systems andmethods usable to operate on a plurality of wells through a single mainbore. One or more chamber junctions are provided in fluid communicationwith one or more conduits within the single main bore. Each chamberjunction includes a first orifice communicating with the surface throughthe main bore, and one or more additional orifices in fluidcommunication with individual wells of the plurality of wells. Throughthe chamber junctions, each of the wells can be individually orsimultaneously accessed. A bore selection tool having an upper openingand at least one lower opening can be inserted into the chamber junctionsuch that the one or more lower openings align with orifices in thechamber junction, enabling selected individual or multiple wells to beaccessed through the bore selection tool while other wells are isolatedfrom the chamber junction. U.S. Patent Application Publication2010/0126729 is herein incorporated by reference in its entirety.

U.S. Pat. No. 5,775,420 discloses a dual completion for gas wellsincluding a dual base with a primary hanger incorporated in the base.Primary and secondary coiled tubing strings extend through the base at adownwardly converging angle of 2 DEG or less. The dual base is mountedon an annular blowout preventer. At the top of the annular blowoutpreventer is a tubing centralizer that aligns the two tubing stringsparallel to one another. The blowout preventer has two side ports belowthe bladder allowing the operator to produce gas from the annulus, toflare gas to atmosphere or to pump in kill fluid in the event of anemergency. The alignment of the tubing strings allows productionrecorders to be run in either string. U.S. Pat. No. 5,775,420 is hereinincorporated by reference in its entirety.

U.S. Pat. No. 3,601,196 discloses a method for perforating in a dual,parallel pipe string tubingless well. A crossover passage or portconnects these pipe strings. Each pipe string is provided with a landingnipple at about the same depth below the crossover port. A radioactivesource tool, which includes a radioactive pill for transmittingradiation in angular directions and a seating member for seating theradioactive source tool in the landing nipple arranged in one of thepipe strings, is pumped through the one pipe string until the seatingmember is landed in the landing nipple. The radioactive pill issuspended from the seating member a predetermined distance which isapproximately the level at which it is desired to perforate. Aperforating assembly, which includes a directional perforating gun, adirectional radiation detector, a radioactivity-sensitive gun-firingmechanism including a source of electrical power for causing actuationof the perforating gun, a rotation device for causing the perforatinggun to rotate, a seating member for seating the perforating assembly inthe landing nipple arranged in the other pipe string, and a locomotivedevice for moving the perforating assembly through the other pipestring, is then pumped through the other pipe string until the seatingmember lands in the landing nipple. The detector of the perforatingassembly is suspended a predetermined distance from the seating memberso that it is positioned at the same level as the radioactive pill inthe adjacent pipe string. The firing mechanism utilizes a switch whichis actuated when the radioactive count detected by the radiationdetector reaches a predetermined level. The directional gun is aimed soas to fire in a predetermined angular direction when the directionaldetector is facing the radioactive pill. The perforating assembly isrotated by circulating fluid in the pipe strings. After the perforatinggun has fired, the perforating assembly is removed from the other pipestring. The radioactive source tool is then removed from the one pipestring. The perforating gun may be reloaded and the perforatingprocedure repeated at a different level in the well bore afterrepositioning the radioactive source tool and perforating assembly. U.S.Pat. No. 3,601,196 is herein incorporated by reference in its entirety.

U.S. Pat. No. 7,066,267 discloses a splitter assembly is positioneddownhole within a conductor for separating two or more tubular stringsplaced within the conductor. A splitter housing may include a first boreand a second bore for separating a first well from a second well, and aplug positioned in one of the bores including a top face slopingdownwardly toward the other bore. One or more guide plates secured tothe splitter housing and positioned above the plug guide a bit or othertool toward one of the first bore and the second bore. The splitterhousing may be positioned along the conductor after the conductor isjetted in place. According to the method, the plug in one of the boresis retrieved after a casing is run in one well, so that the second bitand the second casing will pass through the bore which previouslyincluded the plug. U.S. Pat. No. 7,066,267 is herein incorporated byreference in its entirety.

SUMMARY OF INVENTION

One aspect of the invention provides an offshore oil production system,comprising a structure in a body of water, having a portion extendingabove a surface of the body of water; a surface wellhead located at atop of the body of water; a first wellhead located at a bottom of thebody of water; a second wellhead located at a bottom of the body ofwater; a first riser extending from the first wellhead to the surfacewellhead; and a second riser extending from the second wellhead to thesurface wellhead.

Advantages of the invention include one or more of the following:

Reduced size tree deck on an offshore structure;

Reduced size offshore structure; and/or

Increased number of risers connected to an offshore structure.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic diagram of a multiple wellhead system configuredwith a tension leg platform in accordance with embodiments disclosedherein.

FIG. 2 is a cross-sectional view of a multiple wellhead system inaccordance with embodiments disclosed herein.

FIG. 3 is a schematic diagram of a multiple wellhead system configuredwith a spar platform in accordance with embodiments disclosed herein.

FIG. 4 is a top view of a conventional tree deck of a spar platformhaving single wellheads disposed thereon.

FIG. 5 is a top view of a tree deck on a spar platform having multiplewellhead systems in accordance with embodiments disclosed herein.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to a multiplewellhead system. More specifically, embodiments disclosed herein relateto a multiple wellhead system that may be used in deepwater applicationswith, for example, a tension leg platform (TLP) or a spar platform, orother fixed or floating structures as are known in the art.

FIG. 1

Referring to FIG. 1, a schematic diagram of a TLP multiple wellheadsystem in accordance with embodiments disclosed herein is shown. In thisembodiment, a multiple wellhead 110 may be connected to a TLP 100 toallow fluid to flow from multiple subsea wellheads (e.g., subseawellheads 140 and 150) to TLP 100. In this embodiment, TLP 100 may be anoffshore floating platform above sea level 181. Further, TLP 100 may beused for production of fluids in deepwater applications and may bevertically tethered to seafloor 180 by tethers or tendons (not shown) tomitigate vertical and/or horizontal movement of TLP 100. The tethers ortendons may have a high axial stiffness and a low elasticity to mitigateany vertical movement of TLP 100. However, those having ordinary skillin the art will appreciate that the tethers or tendons may be any typeof structure disposed between the TLP and the sea floor that maymitigate vertical and/or horizontal movement of the TLP.

TLP 100 may include multiple decks and levels (e.g., a main deck 102, aweather deck 104, a rig skid base 105, and a drill floor 109) from whichto secure and suspend drilling and production risers (e.g., a drillingriser 108 and production risers 124 and 134). In this embodiment,drilling riser 108 is suspended by a drilling riser tensioner 107 at rigskid base 105, below drill floor 109. However, those having ordinaryskill in the art will appreciate that a riser may be suspended by atensioner at other various positions on a TLP. Drilling riser tensioner107 may be used to prevent outer drilling riser 108 from experiencingextreme forces that may result from vertical movement of TLP 100 due tocurrents, storms, etc. For example, drilling riser tensioner 107 mayprevent drilling riser 108 from buckling if TLP 100 were to movedownward. Similarly, drilling riser tensioner 107 may prevent outerdrilling riser 108 from experiencing extreme tension forces if TLP 100were to move upward. Although, in this embodiment, TLP 100 is shownhaving a drilling riser and a drilling riser tensioner (e.g., drillingriser 108 and drilling riser tensioner 107) separate from a productionriser and a production riser tensioner (e.g., production risers 124 and134 and production riser tensioner 117), those having ordinary skill inthe art will appreciate that separate drilling risers and tensioners andproduction risers and tensioners may not be necessary. For example, oncedrilling has been completed, a drilling riser may be removed from ariser tensioner and removed from a TLP and one or more production risersmay be configured to engage with the tensioner and may replace thedrilling riser in the TLP.

As shown in FIG. 1, a blowout preventer (BOP) stack 106 is connected toouter drilling riser 108. In this embodiment, BOP stack 106 may beconfigured to seal, control, and monitor an oil or gas well (not shown).BOP stack 106 may also be configured to control pressure changes withinouter drilling riser 108, which may prevent a outer drilling riser 108or drilling or production fluid from being blown out of an oil or gaswell. One having ordinary skill in the art will appreciate that BOPstack 106 may include one or more ram-type BOPs, annular BOPs, orcombinations thereof. Although BOP stack 106 is shown connected to outerdrilling riser 108, those having ordinary skill in the art willappreciate that a BOP stack may be connected to several differenttubular members. For example, a BOP stack may be connected to drillpipe, production pipe, or well casing.

As shown in FIG. 1, multiple wellhead 110 is suspended by a productionriser tensioner 117 at main deck 102, below weather deck 104. However,those having ordinary skill in the art will appreciate that a multiplewellhead may be positioned at various other positions on a TLP. Forexample, production riser tensioner 117 may be used to preventproduction risers 124 and 134 from experiencing extreme forces that mayresult from vertical movement of TLP 100. Further, production risertensioner 117 may prevent production risers 124 and 134 from buckling ifTLP 100 were to move downward. Similarly, production riser tensioner 117may prevent production risers 124 and 134 from experiencing extremetension forces if TLP 100 were to move upward. Those having ordinaryskill in the art will appreciate that a tensioner may be any apparatusor mechanism that may control the vertical position of a tubular member.For example, a tensioner may be a system of hydraulically controlledcylinders that may be operated and adapted to control the verticalposition of a tubular member.

As shown, multiple wellhead 110 is connected to production risers 124and 134. Multiple wellhead 110 allows one or more risers to connectsimultaneously to a single wellhead on a floating platform (e.g., TLP100) and extend downward toward multiple subsea wellheads (e.g., subseawellheads 140 and 150). Although multiple wellhead 110 is shownconnected to two risers, production risers 124 and 134, those havingordinary skill in the art will appreciate that a multiple wellhead maybe connected to one or more risers. For example, a multiple wellhead maybe connected to three or four risers, which may be used to produce fluidfrom multiple subsea wellheads.

As shown in FIG. 1, subsea wellheads 140 and 150 are located on seafloor180 and may provide a suspension point and pressure seals for tubularmembers, such as casing strings, pipes, or risers (e.g., productionrisers 124 and 134). As fluids are produced from the formation throughsubsea wellheads 140 and 150, production risers 124 and 134 allow theproduction fluids to travel from the subsea wellheads 140 and 150 to themultiple wellhead 110 on TLP 100.

FIG. 2

Referring to FIG. 2, a cross-sectional view of a multiple wellheadsystem in accordance with embodiments disclosed herein is shown. In thisembodiment, an outer production riser 212 is connected to a multiplewellhead 210. As shown in FIG. 2, outer production riser 212 extendsfrom multiple wellhead 210 and splits into two outer production risers224 and 234. Those having ordinary skill in the art will also appreciatethat an outer production riser (e.g., outer production riser 212) thatjoins two separate risers (e.g., production riser 224 and 234) may notbe necessary to allow fluid to travel separately to the surface (e.g. tomultiple wellhead 210). For example, two separate production risers maybe separately connected to a multiple wellhead, without the use of anouter riser joining the two risers, and may allow fluid to travelseparately through the two production risers to the surface.

Further, as shown in FIG. 2, production riser 224 includes an outerproduction riser 220 and an inner production riser 222, in which innerproduction riser 222 is disposed within outer production riser 220.Similarly, production riser 234 includes an outer production riser 230and an inner production riser 232, in which inner production riser 232is disposed within outer production riser 230. Having an innerproduction riser (e.g., inner production risers 222 and 232) disposedwithin an outer production riser (e.g. outer production risers 220 and230) may allow the risers to function in extreme pressure environments,such as deepwater environments. For example, having an inner productionriser disposed within an outer production riser in a deepwaterenvironment may mitigate the pressure acting on the inner productionriser, as the outer production riser may serve as a buffer between theinner production riser and the deepwater environment. Further, having aninner production riser disposed within an outer production riser mayalso minimize or prevent the inner production riser from being damagedby the surrounding environment, as the outer production riser mayprotect the inner production riser by shielding the inner productionriser and, again, serving as a buffer between the inner production riserand the surrounding environment.

As shown, a centralizer 260 is disposed within outer production riser212 and may provide both lateral and vertical stability for innerproduction risers 222 and 232, which are also disposed within outerproduction riser 212. Centralizer 260 may be any body or mechanism thatmay provide lateral and vertical stability for inner production risers222 and 232. For example, centralizer 260 may be a plate configured toengage with inner production risers 222 and 232 to provide lateralstability to the inner production risers. Further, the centralizer 260may be a spring or pulley mechanism configured to engage with the innerproduction risers 222 and 232 to provide vertical stability to the innerproduction risers 222 and 232. Further, in one embodiment, a partition215 may be disposed within outer production riser 212. Partition 215 mayextend within outer production riser 212, from multiple wellhead 210 toa junction 219, in which outer production riser 212 splits intoproduction risers 224 and 234. In this embodiment, partition 215 mayseparate inner production risers 222 and 232 within outer productionriser 212. Partition 215 may be any plate, divider, member, or body thatmay provide a physical separation between inner production risers 222and 232.

Although junction 219 is illustrated as being below the water level, insome embodiments, junction 219 is above the water level.

Further, as shown in FIG. 2, production risers 224 and 234 are connectedto subsea wellheads 240 and 250, respectively. Subsea wellheads 240 and250 are located on seafloor 280 and may provide a suspension point andpressure seals for tubular members, such as casing strings, pipes, orrisers (e.g., production risers 224 and 234). As fluids are producedfrom subsea wellheads 240 and 250, production risers 224 and 234 allowthe production fluids to travel from the subsea wellheads 240 and 250 tothe multiple wellhead 210. In this embodiment, fluids that are producedfrom subsea wellheads 240 and 250 travel through tubings (not drawn)insider inner production risers 222 and 232, respectively, to themultiple wellhead 210. However, those having ordinary skill in the artwill appreciate that inner production risers disposed within outerproduction risers may not be necessary to allow fluids to travel fromsubsea wellheads to the surface (e.g. to a multiple wellhead). Forexample, fluids may travel from subsea wellheads through tubular membersthat are connected to the subsea wellheads, such as pipes or riserswithout an interior tubular member disposed within, to the surface.

FIG. 3

Referring to FIG. 3, a schematic diagram of a multiple wellhead systemconfigured with a spar platform in accordance with embodiments disclosedherein is shown. In this embodiment, a multiple wellhead 310 may beconnected to a spar platform 300 to allow fluid to flow from multiplesubsea wellheads (e.g., subsea wellheads 340 and 350) to a spar platform300. In this embodiment, spar platform 300 may be an offshore floatingplatform at sea level 381. Further, spar platform 300 may include acounterweight 311 disposed within a main body 301 of spar platform 300,which may help stabilize spar platform 300. Counterweight 311 of sparplatform 300 may be filled with water or any other material known in theart and may assist in stabilizing spar platform 300 in offshoreconditions. Further, mooring lines (not shown) may be connected to sparplatform 300 and may assist in anchoring spar platform 300 to theseafloor 380. Mooring lines may be flexible members that may connectspar platform 300 to the seafloor 380. Heave plates and buoyancy modules(not shown) may also be provided on body 301.

Spar platform 300 may include multiple decks and levels (e.g., a drillfloor 309 and a cellar deck 302) from which to secure and suspenddrilling and production risers. In this embodiment, production risers324 and 334 are suspended by a production riser tensioner 317 at cellardeck 302, below drill floor 309. However, those having ordinary skill inthe art will appreciate that a riser may be suspended by a tensioner atother various positions on a spar platform.

Production riser tensioner 317 may be used to prevent production risers324 and 334 from experiencing extreme forces that may result fromvertical movement of spar platform 300. For example, production risertensioner 317 may prevent production risers 324 and 334 from buckling ifspar platform 300 were to move downward. Similarly, production risertensioner 317 may prevent production risers 324 and 334 fromexperiencing extreme tension forces if spar platform 300 were to moveupward.

As shown in FIG. 3, multiple wellhead 310 is connected to productionrisers 324 and 334. In this embodiment, multiple wellhead 310 allowsmultiple risers to connect simultaneously to a single wellhead on afloating platform (e.g., spar platform 300) and extend downward towardmultiple subsea wellheads (e.g., subsea wellheads 340 and 350). Asdiscussed above, although multiple wellhead 310 is shown connected totwo risers, production risers 324 and 334, those having ordinary skillin the art will appreciate that a multiple wellhead may be connected toone or more risers. For example, a multiple wellhead may be connected tothree or four risers, which may be used to produce fluid from multiplesubsea wellheads.

Further, as shown in FIG. 3, production risers 324 and 334 exit mainbody 301 of spar platform 300 at a keel point 319 and connect to subseawellheads 340 and 350, respectively. Subsea wellheads 340 and 350 aresituated on seafloor 380 and may provide a suspension point and pressureseals for tubular members, such as casing strings, pipes, or risers(e.g., production risers 324 and 334). As fluids are produced from theformation through tubings (not drawn) to the subsea wellheads 340 and350, production risers 324 and 334 may allow the production fluids totravel through the tubings from the subsea wellheads 340 and 350 to thesurface (e.g., multiple wellhead 310 on spar platform 300).

FIG. 4

Referring to FIG. 4, a top view of a conventional tree deck of a sparplatform having single wellheads disposed thereon is shown.Specifically, FIG. 4 shows a conventional tree deck 474 of a sparplatform 402 having thirty-two single wellheads 412 disposed thereon,each configured to engage with a single riser (not shown). Each risermay be configured to connect with a single subsea wellhead (not shown).As such, the tree deck 474 of spar platform 402 may be configured toconnect with thirty-two subsea wellheads. A tree deck (e.g. tree deck474) may be any deck on an offshore platform (e.g., spar platform 402)in which wellheads and/or BOP trees (e.g. single wellheads 412) arelocated.

FIG. 5

Referring now to FIG. 5, a top view of a tree deck on a spar platformhaving multiple wellheads in accordance with embodiments disclosedherein is shown. Specifically, FIG. 5 shows a top view of a tree deck572 on a spar platform 500 having sixteen multiple wellheads 510, eachconfigured to engage with two risers. As discussed above, each riser maybe configured to connect with a single subsea wellhead. As such, thetree deck 572 of spar platform 500 may be configured to connect withthirty-two subsea wellheads.

Referring generally to FIGS. 4 and 5, although the number of multiplewellheads 510 (sixteen) may be half of the number of wellheads 412(thirty-two), both tree decks 572 and 474 may connect to the same numberrisers (thirty-two) and, thus, connect to the same number of subseawellheads (thirty-two). Because the number of multiple wellheads 510 isless than the number of wellheads 412, as shown in FIGS. 5 and 4,respectively, the surface area of tree deck 572 may be less than thesurface area of tree deck 474. As such, the overall size of sparplatform 500 may be smaller than the overall size of spar platform 402.Although FIGS. 4 and 5 are shown having thirty-two and sixteenwellheads, respectively, those having ordinary skill in the art willappreciate that the number of wellheads on an offshore platform is notlimited to these quantities. For example, an offshore platform mayinclude more or less than the number of wellheads described above.

Although the number of subsea wellheads that may be accessed by risersmay be the same (e.g. thirty-two) in FIGS. 4 and 5, the surface arearequired for tree deck 572 having multiple wellheads 510 may be lessthan the surface area required for tree deck 474 having wellheads 412.Accordingly, the surface area required for a tree deck on a sparplatform may be reduced by increasing the number of risers that may beconfigured with each wellhead on the tree deck. Although FIGS. 4 and 5refer to configurations of a tree deck on a spar platform, those havingordinary skill in the art will appreciate that increasing the number ofrisers that may be configured with each wellhead may reduce the surfacearea required for a tree deck on any deepwater platform. For example,increasing the number of risers that may be configured with eachwellhead may reduce the surface area required for a tree deck on a TLP.

Illustrative Embodiments

In one embodiment, there is disclosed an offshore oil production system,comprising a structure in a body of water, having a portion extendingabove a surface of the body of water; a surface wellhead located at atop of the body of water; a first wellhead located at a bottom of thebody of water; a second wellhead located at a bottom of the body ofwater; a first riser extending from the first wellhead to the surfacewellhead; and a second riser extending from the second wellhead to thesurface wellhead. In some embodiments, the system also includes a firstwellbore extending further into a subsea formation beneath the body ofwater and beneath the first wellhead, and further comprising a secondwellbore extending further into the subsea formation beneath the body ofwater and beneath the second wellhead. In some embodiments, the systemalso includes a production tubing within each of the first wellbore andthe second wellbore. In some embodiments, each production tubing extendsfrom first wellbore and the second wellbore to the surface wellhead. Insome embodiments, the system also includes an outer riser extending fromthe surface wellhead at least a portion of the distance towards thefirst and second wellheads, the first riser and the second riser locatedwithin the outer riser. In some embodiments, the outer riser comprisesat least one divider to separate the riser into at least two regions. Insome embodiments, the first wellbore further comprises a casing string.In some embodiments, the surface wellhead comprises at least two surfacetrees. In some embodiments, the structure comprises a tension legplatform. In some embodiments, the structure comprises a spar platform.

Embodiments described herein may provide for one or more of thefollowing advantages. In accordance with the present disclosure,production fluids may be produced from multiple subsea wellheads to asingle multiple wellhead disposed on a floating platform, such as a TLPor spar platform.

However, those having ordinary skill in the art will appreciate that themultiple wellhead system, described above, may be adapted to be used onfloating platforms other than a TLP or spar platform. Space for multiplewellheads may be limited on an offshore platform for deepwater fluidproduction applications, as construction and maintenance costs mayincrease as the size of the offshore platform increases. Further,constructing and maintaining the offshore platforms may also become morecostly as the size of the offshore platform increases. The multiplewellhead system described above may reduce the number of floatingoffshore platforms needed for producing fluids in deepwater conditions,because the multiple wellhead system may allow fluids to be producedfrom multiple subsea wellheads to a single multiple wellhead on anoffshore platform. Alternatively, any extra space that may be availableon existing offshore platforms as a result of the multiple wellheadsystem, described above, may be used for other equipment and processes.

While the present invention has been described in terms of variousembodiments, modifications in the apparatus and techniques describedherein may be made without departing from the concept of the presentinvention. It should be understood that embodiments and techniquesdescribed in the foregoing are illustrative and are not intended tolimit the scope of the invention.

1. An offshore oil production system, comprising: a structure in a bodyof water, having a portion extending above a surface of the body ofwater; a surface wellhead located at a top of the body of water; a firstwellhead located at a bottom of the body of water; a second wellheadlocated at a bottom of the body of water; a first riser extending fromthe first wellhead to the surface wellhead; and a second riser extendingfrom the second wellhead to the surface wellhead.
 2. The system of claim1, further comprising a first wellbore extending further into a subseaformation beneath the body of water and beneath the first wellhead, andfurther comprising a second wellbore extending further into the subseaformation beneath the body of water and beneath the second wellhead. 3.The system of claim 2, further comprising a production tubing withineach of the first wellbore and the second wellbore.
 4. The system ofclaim 3, wherein each production tubing extends from first wellbore andthe second wellbore to the surface wellhead.
 5. The system of claim 1,further comprising an outer riser extending from the surface wellhead atleast a portion of the distance towards the first and second wellheads,the first riser and the second riser located within the outer riser. 6.The system of claim 5, wherein the outer riser comprises at least onedivider to separate the riser into at least two regions.
 7. The systemof claim 2, wherein the first wellbore further comprises a casingstring.
 8. The system of claim 1, wherein the surface wellhead comprisesat least two surface trees.
 9. The system of claim 1, wherein thestructure comprises a tension leg platform.
 10. The system of claim 1,wherein the structure comprises a spar platform.